Rotating drilling towers

ABSTRACT

Two or more rotating towers on a drilling rig may be configured to rotate between one or more wells. The rotating towers may have a common well center, such that the two or more towers can operate over the same well to provide redundant or cooperative operations. Some example cooperative operations include heavy lifting and/or isochronous tripping operations. Redundancy can be provided by the two or more rotating towers to prevent equipment failures from halting operations.

CROSS-REFERENCE TO RELATED PATENT APPLICATIONS

This application claims the benefit of U.S. Provisional PatentApplication No. 62/426,415 to Daniel Haslam entitled “Rotating DrillingTowers” and filed on Nov. 25, 2016, and claims the benefit of U.S.Provisional Patent Application No. 62/331,653 to Daniel Haslam entitled“Rotating Drilling Towers” and filed on May 4, 2016, both of which areincorporated by reference.

BACKGROUND Field of Invention

The present invention relates generally to well construction, and morespecifically, but not by way of limitation, to use one or more rotatabledrilling towers to perform various drilling operations, such as may beperformed on a drilling vessel.

Description of Related Art

Drilling an oil or gas well conventionally involves operating a single,fixed drilling tower (or mast or derrick) to hoist (e.g., load/unload)tubulars and other equipment along a fixed path below or to the side ofthe drilling tower. The fixed nature of the drilling tower limitsdrilling operations to a single well located below or next to thedrilling tower. Because only a single, fixed tower is used, drillingoperations cease if the drilling tower requires maintenance or if anydrilling tower equipment (e.g., hoisting, circulating, rotating,auxiliary equipment) fails. To mitigate these costly delays, operatorsand innovators schedule maintenance when not drilling and designdrilling towers such that maintenance can be performed outside thecritical drilling path. While helpful, these solutions still incurdelays and do not account for unplanned events such as equipment and/orprocedural failures.

Delays also occur when changing equipment, because such equipment mustbe configured along the drilling path. Further delays occur when using afixed drilling tower during tripping operations. Tripping operationsfeed or pull individual segments of pipe into or out of a well. Eachpipe or tubular is fed into or out of the well one at a time andconnected or disconnected from the prior pipe or tubular by threading.Tripping requires heavy equipment like hoisting and rotating equipmentand is conventionally a very time consuming process. One time-consumingaspect of conventional tripping is the requirement of the hoistingsystem to reposition in an unloaded state after raising or lowering theentire weight of the tubing string. This repositioning takes time thatcould otherwise be used to continue tripping operations.

Another drawback of traditional fixed drilling towers is that theygenerally must be designed to hoist the largest potential load, even ifhoisting such a large load is infrequent. This requires the tower to beheavier and more expensive than usually needed, increases maintenancecosts, and can reduce operating efficiency (due to the slow travelingspeeds of the load path under all load conditions). Adjustable hoistingcapacity technology, such as variable cylinder rig designs wherecylinders can be taken offline, can compromise tripping efficiencybecause they still require the traveling block to large enough to handlethe largest load, and variable cylinder rig designs do not allow theblock to retract off the drilling path.

SUMMARY

One or more rotating towers may be located on a drilling rig to improveupon the drawbacks of conventional technology described above, whileadditionally offering other benefits. For example, rotating towers mayreduce delays, such as the delays described above that occur inconventional drilling rigs. Furthermore, greater operational flexibilityis achieved because the one or more towers can perform operations offthe critical path.

The one or more rotating towers may be configured to rotate about theirvertical centerlines to lift, lower, move, or hold a load along theirrespective rotation paths. In some embodiments, the one or more towerscan be capable of supporting operations or activities outside thecritical path of a well, such as transverse movement of loads ormaintenance. In some embodiments, the one or more drilling towers caninclude counterbalances. In some embodiments, the one or more towers caninclude active or passive compensation mechanisms to compensate forforces generated by ocean waves or other factors. In some embodiments,the one or more towers can include adjustable crown sheaves capable oftransversely positioning the path of a load carried by the one or moretowers. In some embodiments, the one or more towers can include one ormore traveling assemblies, drill lines, retraction mechanisms, hooks,top drives, swivels, blocks, and/or block-and-tackles.

In some configurations, the two towers can be used with at least one ofthe towers configured to rotate between more than one well. For example,the two towers can be disposed close enough to each other so that theirrespective rotational paths at least partially overlap. In someembodiments, both towers can rotate over the same well. In someembodiments, more than one well can be located at asymmetrical positionsalong at least one of the paths of the two towers. In some embodiments,a well can be located off boat longitudinal axis, off the circularrotational path of at least one tower, or both. In some embodiments, therotational path of at least one of the towers can be off-center. In someembodiments, at least one of the towers can include adjustable crownsheaves capable of transversely positioning the path of a load carriedby the tower(s) in order to reach a well located outside the circularrotational path of the tower(s). In some embodiments, the two towers areseparate, independent units. In some embodiments, operations carried outby one tower do not affect or depend on operations carried out by theother tower. Some of these configurations may provide (i) increasedoperational flexibility because more than one well can be operated by asingle tower; (ii) higher operation uptime due to increasedmaintainability, redundancy, and the ability to recover from unplannedevents without delaying operations; and (iii) lower maintenance costsdue to the ability to perform maintenance and equipment dressing off thecritical path.

Two towers can be used with both towers configured to rotate over thesame well center and perform operations over that well center at thesame time. In some embodiments, the drill lines of the two towers can beconfigured to facilitate cooperation. For example, the drill lines ofeach tower can be offset or employ different drill line terminationpoints than each other so that they do not interfere; or the towers canbe positioned at different fixed or variable heights. In someembodiments, telescoping means may be provided in one of the drillingtowers to provide variable height. In some embodiments, the two towerscan cooperate to raise, lower, or hold a load. In some embodiments, thetwo towers can cooperate to isochronously, continuously, orconventionally perform tripping operations. In some embodiments,tubulars used in tripping operations can be stored and/or retrieved fromvarious locations, including within the hull of a rig (e.g., amoonpool), on a rig floor, or horizontally on a pipe deck or in adedicated hold. In some embodiments, the two towers can cooperativelyoperate a single top drive to perform an operation. In some embodiments,the two towers can operate two top drives cooperatively to perform asingle operation. In some embodiments, each tower can be optimized tohoist the most frequently encountered load, rather than the heaviestanticipated load, of an operation. In some embodiments, the two towerscan be configured to together hoist the maximum anticipated load for agiven operation. In some embodiments, the two towers can include a braceto resist the force or moment created when lifting, lowering, or holdinga load. In some embodiments, the brace can be located between andcoupled to the two towers. In some embodiments, the brace can be locatedabove the highest possible vertical location of one or more travelingassemblies and/or other equipment of the towers. In some embodiments,the brace can include one or more brace supports that can circumscribeand/or couple to at least one of the two towers. In some embodiments,the one or more brace supports can be configured to permit the at leastone of the two towers to rotate and/or telescope substantially freelywhile not substantially limiting the movement of one or more travelingassemblies and/or other equipment of the towers. Some of theseconfigurations may provide (i) lower initial capital expendituresbecause less equipment and/or less robust equipment is needed; (ii)lower maintenance costs because the towers operate a less amount ofand/or less heavy hoisting equipment; and (iii) increased efficiency intripping operations because tripping operations can continue duringunloaded travel.

The term “coupled” is defined as connected, although not necessarilydirectly, and not necessarily mechanically; two items that are “coupled”may be unitary with each other. The terms “a” and “an” are defined asone or more unless this disclosure explicitly requires otherwise. Theterm “substantially” is defined as largely but not necessarily whollywhat is specified (and includes what is specified; e.g., substantially90 degrees includes 90 degrees and substantially parallel includesparallel), as understood by a person of ordinary skill in the art. Inany disclosed embodiment, the terms “substantially” and “approximately”may be substituted with “within [a percentage] of” what is specified,where the percentage includes 0.1, 1, 5, and 10 percent.

The phrase “and/or” means and or or. To illustrate, A, B, and/or Cincludes: A alone, B alone, C alone, a combination of A and B, acombination of A and C, a combination of B and C, or a combination of A,B, and C. In other words, “and/or” operates as an inclusive or.

Further, a device or system that is configured in a certain way isconfigured in at least that way, but it can also be configured in otherways than those specifically described.

The terms “comprise” (and any form of comprise, such as “comprises” and“comprising”), “have” (and any form of have, such as “has” and“having”), and “include” (and any form of include, such as “includes”and “including”) are open-ended linking verbs. As a result, an apparatusthat “comprises,” “has,” or “includes” one or more elements possessesthose one or more elements, but is not limited to possessing only thoseelements. Likewise, a method that “comprises,” “has,” or “includes,” oneor more steps possesses those one or more steps, but is not limited topossessing only those one or more steps.

BRIEF DESCRIPTION OF THE DRAWINGS

The following drawings illustrate by way of example and not limitation.For the sake of brevity and clarity, every feature of a given structureis not always labeled in every figure in which that structure appears.Identical reference numbers do not necessarily indicate an identicalstructure. Rather, the same reference number may be used to indicate asimilar feature or a feature with similar functionality, as maynon-identical reference numbers.

FIG. 1a depicts rotating drilling towers operating over different wellsaccording to some embodiments of the disclosure.

FIG. 1b depicts rotating drilling towers operating over the same wellaccording to some embodiments of the disclosure.

FIGS. 1c and 1d depict an adjustable crown sheave system according tosome embodiments of the disclosure.

FIG. 2a depicts two rotating drilling towers performing “heavy lift”operations, according to some embodiments of the disclosure.

FIG. 2b depicts a top view of an embodiment of a brace, according someembodiments of the disclosure.

FIG. 2c is a flow chart illustrating a method of performing a “heavylift” operation, according to the embodiments disclosed in FIG. 2 a.

FIG. 2d is a flow chart illustrating a method of performing a “heavylift” operation, according to some embodiments of the disclosure.

FIG. 3a depicts a first step of running tubing out of a well by anisochronous tripping operation, according to some embodiments of thedisclosure.

FIG. 3b depicts a second step of running tubing out of a well by anisochronous tripping operation, according to some embodiments of thedisclosure.

FIG. 3c depicts a third step of running tubing out of a well by anisochronous tripping operation, according to some embodiments of thedisclosure.

FIG. 3d depicts a fourth step of running tubing out of a well by anisochronous tripping operation, according to some embodiments of thedisclosure.

FIG. 3e depicts a fifth step of running tubing out of a well by anisochronous tripping operation, according to some embodiments of thedisclosure.

FIG. 3f depicts a sixth step of running tubing out of a well by anisochronous tripping operation, according to some embodiments of thedisclosure.

FIG. 3g depicts a seventh step of running tubing out of a well by anisochronous tripping operation, according to some embodiments of thedisclosure.

FIG. 3h depicts an eighth step of running tubing out of a well by anisochronous tripping operation, according to some embodiments of thedisclosure.

FIG. 3i is a flow chart illustrating a method of performing anisochronous tripping operation, according to some of the embodimentsdisclosed in FIGS. 3a -3 h.

FIG. 3j is a flow chart illustrating a method of performing anisochronous tripping operation, according to some embodiments of thedisclosure.

FIG. 4a depicts a first step of running tubing into a well by anisochronous tripping operation, according to some embodiments of thedisclosure.

FIG. 4b depicts a second step of running tubing into a well by anisochronous tripping operation, according to some embodiments of thedisclosure.

FIG. 4c depicts a third step of running tubing into a well by anisochronous tripping operation, according to some embodiments of thedisclosure.

FIG. 4d depicts a fourth step of running tubing into a well by anisochronous tripping operation, according to some embodiments of thedisclosure.

FIG. 4e depicts a fifth step of running tubing into a well by anisochronous tripping operation, according to some embodiments of thedisclosure.

FIG. 4f depicts a sixth step of running tubing into a well by anisochronous tripping operation, according to some embodiments of thedisclosure.

FIG. 4g depicts a seventh step of running tubing into a well by anisochronous tripping operation, according to some embodiments of thedisclosure.

FIG. 4h depicts an eighth step of running tubing into a well by anisochronous tripping operation, according to some embodiments of thedisclosure.

FIG. 4i is a flow chart illustrating a method of performing anisochronous tripping operation, according to some of the embodimentsdisclosed in FIGS. 4a -4 h.

FIG. 4j is a flow chart illustrating a method of performing anisochronous tripping operation, according to some embodiments of thedisclosure.

DETAILED DESCRIPTION

Referring to the drawings, FIGS. 1a and 1b depict differentconfigurations of drilling operation 100, which includes two rotatingdrilling towers (or masts or derricks) 101 a, 101 b. Drilling towers 101a, 101 b can perform various well operations, including those thatemploy hoisting, circulating, rotating, and/or auxiliary equipment.Drilling towers 101 a, 101 b may each include a set of sheaves 102, 104(e.g., a crown sheave cluster) and a traveling assembly (not shown)located under sheave 104. Though not shown, drilling towers 101 a, 101 bcan also include other components of drilling towers, including a motioncompensating device, which can be any mechanism capable of compensatingfor the relative movement of the drilling towers versus the seabed. Thetraveling assemblies of towers 101 a, 101 b can retract transverselytoward and away from towers 101 a, 101 b when performing the variouswell construction operations. Drilling towers 101 a, 101 b may beincluded in an offshore vessel such as an oil rig or drilling vessel.When used in such an application, compensation mechanisms may beintegrated with drilling towers 101 a, 101 b to compensate for themotion induced by ocean waves and/or other forces generated on theoffshore vessel or drilling towers. The compensation mechanisms can beactive or passive compensation systems. Drilling towers 101 a, 101 b canrotate about their vertical centerlines (i.e., out of the page) to lift,lower, move, or hold a load anywhere along their respective rotationalpaths 105, 106 (shown in dashed lines). Additionally, the travelingassemblies of towers 101 a, 101 b can be retracted toward or away fromtowers 101 a, 101 b to increase or decrease the diameter of rotationalpaths 105, 106. The diameter of rotational paths 105, 106 can also beadjusted by employing an adjustable crown sheave system on towers 101 a,101 b, such as system 123.

FIGS. 1c and 1d show side views of adjustable crown sheave system 123disposed on a tower 101 (e.g., tower 101 a or tower 101 b). Adjustablecrown sheave system 123 includes two crown sheaves 102, 104 mounted tothe top of tower 101 via mounting assemblies 124. Mounting assemblies124 can be configured to permit crown sheaves 102, 104 to movetransversely (i.e., left or right, as depicted) via, e.g., rotation ofbars 125 about pins 126. Mounting assemblies 124 can further includestops 127 on either side of bars 125 that restrict the transverse motionof crown sheaves 102, 104. Crown sheaves 102, 104 can move transverselyvia operation of tie-bar 128. As seen by comparing FIG. 1c to FIG. 1d ,tie-bar 128 can decrease or increase its transverse length via, e.g, asliding mechanism. Tie-bar 128 can be operated manually or remotely andcan be operated by mechanical, electrical, hydraulic, or other means.When tie-bar 128 is actuated to reduce its transverse length from thelength shown in FIG. 1c to the length shown in FIG. 1d , the operationalpath 129 of drill line 132 moves from a distance 130 away from tower 101to a shorter distance 131 away from tower 101, thus decreasing thediameter of the rotational path of tower 101.

Towers 101 a, 101 b may be located close enough to one another such thattheir respective rotational paths can at least partially overlap. Well103 a lies along path 105 such that drilling tower 101 a can performoperations on well 103 a, while well 103 b lies along path 106 such thatdrilling tower 101 b can perform operations on well 103 b. Well 103 clies along both paths 105 and 106 such that both drilling towers 101 a,101 b can perform operations on well 103 c. While shown symmetrically,wells 103 a-c (or other wells) can also be located at asymmetricalpositions. For example, wells can be located off boat longitudinal axis,off the circular rotational paths of towers 101 a, 101 b, or both. Tofacilitate operation of these wells by towers 101 a, 101 b, therotational path of either or both towers 101 a, 101 b can be off-center(e.g., oval). An off-center rotational path can be accomplished in atleast one of two ways. First, an off-center rotational path can beaccomplished by retraction of the traveling assemblies toward or awayfrom towers 101 a, 101 b during rotation. Second, an off-centerrotational path can be accomplished by employing an adjustable crownsheave system, such as system 123 shown in FIGS. 1c and 1d , on towers101 a, 101 b.

Each tower 101 a, 101 b may be configured and operated as a separate,independent unit. Operations carried out on one tower (e.g. tower 101 a)do not affect nor depend on operations of another tower (e.g., tower 101b). Towers 101 a, 101 b are capable of supporting activities outside thecritical path of a well, such as transverse movement of heavy loads ormaintenance. While towers 101 a, 101 b can perform different operationssimultaneously, they also provide redundancy that prevents delays. Forexample, if tower 101 b requires maintenance or its equipment fails, itcan rotate away from operation over well 103 c (e.g., to being over well103 b) and tower 101 a can rotate from operation over well 103 a tocontinue the operation over well 103 c. This can reduce downtimeexposure and provide additional operational flexibility when performingmaintenance as the maintenance can be performed off the critical pathover well 103 c. Additionally, towers 101 a, 101 b can be dressed forthe next operation off the critical path over well 103 c (e.g.,converted from a configuration to run riser segments to a configurationto run drill pipe) and then rotated over the critical path over well 103c without delaying operations.

Towers 101 a, 101 b can also operate simultaneously or in combinationover the same well, as shown in FIG. 1b . To facilitate cooperation,towers 101 a and 101 b can be configured in a variety of ways. Forexample, the drill lines of towers 101 a, 101 b can be offset or employdifferent drill line termination points in order to ensure that they donot interfere. Drilling towers 101 a, 101 b can also be at differentfixed heights or use telescoping means to adjust the height of either orboth towers.

When operating simultaneously or in combination over the same well,towers 101 a, 101 b can perform a variety of useful operations. Forexample, towers 101 a, 101 b can together raise, lower, or hold a load,referred to herein as a “heavy lift operation” (see FIGS. 2a-2b andaccompanying description), or can cooperate to isochronously triptubulars in and out of a well (see FIGS. 3a-4h and accompanyingdescription). During isochronous tripping, the tripping speed may bemaintained constant over a given range of block speeds. Towers 101 a,101 b can also be used in conjunction to trip tubulars in other ways.For example, towers 101 a and 101 b could be used in a continuoustripping operation. Tubulars used for tripping may be stored in and fedto towers 101 a, 101 b from various locations, including within the hull(e.g., a moonpool), on the rig floor, or horizontally on a pipe deck orin dedicated holds.

FIG. 2a depicts a heavy lift operation 200, wherein two rotatingdrilling towers 201 a, 201 b work together to lift a tubing string 207,214 into or out of well 203 located below floor 210. Heavy liftoperation 200 employs a vertical traveling mechanism 219 comprising atop drive 208 coupled to retraction mechanisms 209 a, 209 b, as well asother components such as a hook (not shown). Retraction mechanisms 209a, 209 b are coupled to tower 201 a, 201 b, respectfully, and may beconfigured to move top drive 208 transversely (left and right, asdepicted). In some embodiments, as shown in FIG. 2a , one topdrive hasbeen removed and both retraction mechanisms are shown connected to asingle topdrive. In some embodiments, the retraction mechanisms can nolonger move 208 transversely and can only align it over well center 103c. In some embodiments, a topdrive is moved transversely when oneretraction mechanism is connected to its own topdrive.

The top drive 208 can be a conventional top drive or other mechanismsuch as a swivel. While each tower 101 a, 101 b normally employs its owntop drive (or swivel), when used in combination, one of the tower's topdrives can be removed from its retraction mechanism (209 a or 209 b) andthe unloaded retraction mechanism coupled to the other tower's topdrive. Alternatively, both tower top drives may be coupled together sothat both work in concert. Top drive 208 shown in FIG. 2a represents atleast either of these embodiments.

In operation, traveling assembly 219 lifts or lowers a heavy tubingstring or other load into or out of a wellbore using the combined powerof towers 201 a, 201 b. The lifting or lowering force is suppliedthrough drill lines 232 a, 232 b coupled to block and tackle assemblies202 a, 211, 219 and 202 b, 211, 219 respectively although other hoistingmeans are also contemplated. Each tower 201 a, 201 b can be capable ofindividually lifting a load of approximately half the load 207, 214.Thus, the towers used in heavy lift operation 200 can each be designedto hoist the most frequently occurring, rather than heaviest anticipatedload, because when heavy loads are encountered the two towers mayoperate in combination. During heavy lift operations, components on bothtowers may be operated together to obtain the additional power to liftthe heavy loads.

Heavy lift operation 200 can also employ a brace 220 that can be coupledto each of towers 201 a, 201 b and located above the highest possiblevertical location of traveling assembly 219 (though not necessarily inthe same transverse location as traveling assembly 219). Brace 220 canbe any configuration capable of resisting, at least in part, the force(moment) generated on towers 201 a, 201 b when lifting, lowering, orholding load 207, 214, including the configuration shown in FIG. 2b ,which shows a top view. Brace 220 includes brace supports 222 thatcircumscribe and couple to towers 201 a, 201 b. Brace supports 222permit towers 201 a, 201 b to rotate and/or telescope substantiallyfreely while not substantially limiting the movement of travelingassembly 219.

A heavy lift operation using the towers shown in FIG. 2a can beperformed according to the method shown in FIG. 2c . For example, towers201 a, 201 b can first be rotated over well 203 such that theirrespective traveling assemblies do not interfere (e.g., they can be in aretracted position). To allow towers 201 a, 201 b to perform a singleoperation (e.g., hoisting, lowering, or transversely moving an object),the traveling assemblies of towers 201 a, 201 b can be configured tooperate in concert according to either of the systems described above.For example, tower 201 a's top drive can be removed from its retractionmechanism 209 a. Retraction mechanism 209 a can then be coupled to tower201 b's top drive in an operative manner. As an alternative, the bottomof tower 201 a's top drive can be coupled to the top of tower 201 b'stop drive (or vice versa) and the top drives configured to operate as asingle top drive (e.g., by electronic or mechanical means). In someembodiments, the drive mechanism of one of the top drives can bedisabled so that its rotation is a passive part of the top drive 208.Once configured, top drive 208 can be coupled (e.g., hooked) to tubular207 disposed in well 203. Power transmitted through block and tackleassemblies 202 a, 202 b, 211, 219 of towers 201 a and 201 b can then beused hoist, lower, hold, or otherwise move tubular 207, for example outof well 203.

More generally, a method for heavy lift operations is described withreference to FIG. 2d . Such a method comprises first rotating first andsecond towers over the same well; second, configuring the first andsecond towers to cooperatively hoist an object; third, coupling theobject to the first and second towers; and fourth, hoisting the objectusing the combined power of the first and second towers.

FIGS. 3a-3i depict isochronous tripping-out method 300 using multiplerotating drilling towers 301 a, 301 b, which may be located on a rigfloor 310 when installed on a drilling vessel. Each tower 301 a, 301 bhas a vertical traveling assembly 319 a, 319 b, respectively, comprisinga top drive (or swivel) 308 a, 308 b, respectively, and a retractingmechanism 309 a, 309 b, respectively. As shown in FIG. 3a , travelingassembly 319 a may be initially centered over well 303 and coupled(e.g., hooked) to tubular 307, which is the top tubular of a tubularstring disposed in well 303. At the same time, traveling assembly 319 bis initially disposed vertically above but transversely adjacent totraveling assembly 319 a and is in a retracted position (e.g., retractedtoward tower 301 b) such that it is not centered over well 303. As shownin FIG. 3b , traveling assembly 319 a lifts tubular 307 (and the tubingstring to which it is attached) out of the well in direction 312 whiletraveling assembly 319 b moves in direction 313. Travel assembly 319 bremains in the retracted position while traveling in direction 313 suchthat traveling assembly 319 a and tubular 307 pass by traveling assembly319 b moving in direction 312.

As shown in FIG. 3c , traveling assembly 319 a continues upward untiltubular 307 is entirely out of well 303 and tubular 314 (the nexttubular in the tubing string) is partially out of well 303 (i.e., atbreak-out height for tubular 307). Traveling assembly 319 b continuesdownward until its lower end (the lower end of top drive 308 b) is justvertically above but transversely adjacent to the top of tubular 314.Top drive 308 a then disconnects tubular 307 from tubular 314 (e.g., byrotation or other means). Retraction mechanism 309 a retracts top drive308 a and tubular 307 transversely toward tower 301 a, as shown in FIG.3d . Tubular 307 can then be removed from top drive 308 a by othertubular handling equipment (not shown) or lowered by traveling assembly319 a and removed later, as described below with reference to FIGS. 3eand 3f . At the time tubular 307 is moved off the well center (orshortly after), retraction mechanism 309 b moves top drive 308 btransversely away from tower 301 b until it is centered over tubular314. Traveling assembly 319 b then couples (e.g., hooks) to tubular 314.

As shown in FIG. 3e , traveling assembly 319 b then lifts tubular 314(and the tubing string to which it is attached) in direction 312 whileremaining centered over well 303. At the same time, traveling assembly319 a and tubular 307, if not already removed, move in direction 313while traveling assembly 319 a remains in a retracted position such thattraveling assembly 319 a and tubular 307 can pass by traveling assembly319 b and tubular 314. As shown in FIG. 3f , traveling assembly 319 bcontinues to lift tubular 314 until tubular 314 is entirely out of well303 and tubular 315 (the next tubular in the tubing string) is partiallyout of well 303 (e.g., at break-out height for tubular 314). Travelingassembly 319 a and tubular 307, if not already removed, continue to movein direction 313 until lower end of traveling assembly 319 a (the lowerend of top drive 308 a) is just vertically above but transverselyadjacent to tubular 315. Unless already removed, traveling assembly 319a then uncouples from tubular 307. Tubular 307 can be stored in variouslocations including below rig floor 310 (e.g., in a moon pool), on rigfloor 310, or horizontally on a pipe deck or in dedicated holds. Topdrive 308 b then disconnects tubular 314 from tubular 315 (e.g., throughrotation or other means).

Retraction mechanism 309 b then retracts top drive 308 b and tubular 314transversely toward tower 301 b, as shown in FIG. 3g . Tubular 314 canthen be removed from top drive 308 b by other tubular handling equipment(not shown) or lowered by traveling assembly 319 b and removed later. Atthe time tubular 314 is moved off the well center (or shortly after),retraction mechanism 309 a moves top drive 308 a transversely away fromtower 301 a until it is centered over tubular 315. Traveling assembly319 a then couples (e.g., hooks) to tubular 315. As shown in FIG. 3h ,traveling assembly 319 a then lifts tubular 315 (and the tubing stringto which it is attached) in direction 312 while remaining centered overwell 303. At the same time, traveling assembly 319 b and tubular 314, ifnot already removed, move in direction 313 while traveling assembly 319b remains in a retracted position such that traveling assembly 319 b andtubular 314 can pass by traveling assembly 319 a and tubular 315. Theprocess of tripping tubulars out of well 303 can then continue accordingthe process just described.

A summary of isochronous tripping-out method 300 is depicted in FIG. 3i. In particular, FIG. 3i broadly describes the steps shown in at leastFIGS. 3a-g , including: (1) rotating towers 301 a, 301 b over the samewell 303, while the traveling assemblies 319 a, 319 b are in therespective retracted positions (i.e., close to towers 301 a, 301 b,respectively); (2) lowering traveling assembly 319 a to a position justabove but transversely adjacent to the top of tubular 307 (i.e.,break-out height) while traveling assembly 319 b is positioned near thetop of tower 301 b still in its retracted position; (3) moving top drive319 a away from its retracted position against tower 301 a and couplingtop drive 308 a to tubular 307 via, e.g., a hook; (4) hoisting tubular307 and the tubing string to which it is coupled out of well 303 viatraveling assembly 319 a to the break-out height for tubular 307 while,at about the same time, lowering traveling assembly 319 b to break outheight for tubular 307 in anticipation of tubular 307 being removed fromtubular 314; (5) removing tubular 307 from tubular 314 (e.g., viathreading) and retracting top drive 308 a and tubular 307 away from thecenter of well 303 toward tower 301 a; (6) moving top drive 308 b awayfrom tower 301 b via, e.g., retraction mechanism 309 b and coupling topdrive 308 b to tubular 314 via, e.g., a hook; optionally, removingtubular 307 from traveling assembly 319 a while tubular 307 is still atbreak out height and storing tubular 307, e.g., on or under rig floor310; (7) hoisting tubular 314 and the tubing string to which it iscoupled out of well 303 via traveling assembly 319 b to the break-outheight of tubular 314 while, at about the same time, lowering travelingassembly 319 a (and tubular 307, if not already removed) to break outheight for tubular 314 in anticipation of tubular 314 being removed fromtubular 315; (8) if not already removed, removing tubular 307 fromtraveling assembly 319 a and storing tubular 307, e.g., on or under rigfloor 310, while also removing tubular 314 from tubular 315 (e.g., viathreading); and (9) retracting top drive 308 b and tubular 314 away fromthe center of well 303 toward tower 301 b. Steps 3-9 can then berepeated for subsequent tubulars (modifying step 4 to remove any coupledtubular from traveling assembly 319 b, if not previously removed) untiltubular desired to be removed from well 303 have been removed from well303.

More generally, a method for isochronously tripping tubulars out of awell is described with reference to FIG. 3j . Such a method may include:rotating first and second towers over the same well with both towerspositioned off the center of the well; positioning the first tower overthe center of the well, coupling the first tower to a first tubulardisposed in the well, hoisting the first tubular out of the well byoperation of the first tower, and decoupling the first tubular from thetubing string; and storing the first tubular (e.g. on or under a deck ofa rig) while positioning the second tower over the center of the well,coupling the second tower to a second tubular disposed in the well(i.e., the next tubular in the tubing string), hoisting the secondtubular out of the well by operation of the second tower, and decouplingthe second tubular from the tubing string. The second and third stepscan then be repeated with subsequent tubulars (modifying the second stepto further store any tubular coupled the second tower) until all tubulardesired to be removed from the well are removed from the well.

FIGS. 4a-4h depict isochronous tripping-in method 400, which employsmultiple rotating drilling towers 401 a, 401 b disposed on rig floor410. Each tower 401 a, 401 b has a vertical traveling assembly 419 a,419 b, respectively, comprising a top drive (or swivel) 408 a, 408 b,respectively, and a retracting mechanism 409 a, 409 b, respectively. Asshown in FIG. 4a , traveling assembly 419 b is initially centered overwell 403 and coupled (e.g., hooked) to tubular 416, which is entirelyoutside well 403. Tubular 416 is connected to tubular 417 that ispartially disposed within well 403 (i.e., at make-up height). Travelingassembly 419 a is initially disposed vertically below but transverselyadjacent to traveling assembly 419 b and is in a retracted position(e.g., retracted toward tower 401 a) such that it is not centered overwell 403. Tubular 415 can be introduced by other tubular handlingequipment (not shown) or coupled (e.g., hooked) to traveling assembly419 a, as shown. Tubular 415 and other tubulars can be retrieved fromvarious locations including below rig floor 410 (e.g., in a moon pool),on rig floor 410, or horizontally on a pipe deck or in dedicated holds.

As shown in FIG. 4b , traveling assembly 419 a lifts tubular 415 indirection 412 while traveling assembly 419 b lowers tubulars 416, 417 indirection 413 into well 403. Travel assembly 419 a remains in theretracted position (i.e., toward tower 401 a) while moving in direction412 such that traveling assembly 419 a and tubular 415 pass by travelingassembly 419 b and tubulars 416, 417.

As shown in FIG. 4c , traveling assembly 419 a continues to lift tubular415 until the bottom of tubular 415 is just vertically above buttransversely adjacent to the top of tubular 416 (i.e., at make-upheight). Traveling assembly 419 b continues in direction 413 untiltubular 417 is entirely within well 403 and the top of tubular 416 isjust below but transversely adjacent to the bottom of tubular 415 (i.e.,at make-up height). Top drive 408 b then disconnects (e.g., unhooks)from tubular 416 (e.g., by rotation or other means). Retractionmechanism 409 b then retracts top drive 408 b transversely toward tower401 b, as shown in FIG. 4d . Tubular 414 can be introduced by othertubular handling equipment (not shown) or coupled (e.g., hooked) totraveling assembly 419 b, as shown. Tubular 414 and other tubulars canbe retrieved from various locations including below rig floor 410 (e.g.,in a moon pool), on rig floor 410, or horizontally on a pipe deck or indedicated holds. At the time top drive 408 b moves off the well center(or shortly after), retraction mechanism 409 a moves top drive 408 a andtubular 415 transversely away from tower 401 a until centered overtubular 416. Top drive 408 a then connects tubular 415 to tubular 416(e.g., by rotation or other means).

As shown in FIG. 4e , traveling assembly 419 b then lifts tubular 414 indirection 412 while traveling assembly 419 a lowers tubulars 415, 416 indirection 413 into well 403. Traveling assembly 419 b remains in theretracted position (i.e., toward tower 401 b) while moving in direction412 such that traveling assembly 419 b and tubular 414 pass by travelingassembly 419 a and tubulars 415, 416 moving in direction 413.

As shown in FIG. 4f , traveling assembly 419 b continues to lift tubular414 until the bottom of tubular 414 is just vertically above buttransversely adjacent to the top of tubular 415 (i.e., at make-upheight). Traveling assembly 419 a continues in direction 413 untiltubular 416 is entirely within well 403 and the top of the tubular 415is just below but transversely adjacent to the bottom of tubular 414(i.e., at make-up height). Top drive 408 a then disconnects (e.g.,unhooks) from tubular 415 (e.g., by rotation or other means). Retractionmechanism 409 a then retracts top drive 408 a transversely toward tower401 a, as shown in FIG. 4g . Tubular 407 can be introduced by othertubular handling equipment (not shown) or coupled (e.g., hooked) totraveling assembly 419 a, as shown. Tubular 407 and other tubulars canbe retrieved from various locations including below rig floor 410 (e.g.,in a moon pool), on rig floor 410, or horizontally on a pipe deck or indedicated holds. At the time top drive 408 a moves off the well center(or shortly after), retraction mechanism 409 b moves top drive 408 b andtubular 414 transversely away from tower 401 b until centered overtubular 415. Top drive 408 b then connects tubular 414 to tubular 415(e.g., by rotation or other means).

As shown in FIG. 4h , traveling assembly 419 a then lifts tubular 407 indirection 413 while traveling assembly 419 a lowers tubulars 414, 415 indirection 413 into well 403. Traveling assembly 419 a remains in theretracted position (i.e., toward tower 401 a) while moving in direction412 such that traveling assembly 419 a and tubular 407 pass by travelingassembly 419 b and tubular 414, 415 moving in direction 413. The processof tripping tubulars into well 403 can then continue according theprocess just described.

A summary of isochronous tripping-in method 400 is shown in FIG. 4i . Inparticular, FIG. 4i broadly describes the steps shown in at least FIGS.4a-g , including: (1) rotating towers 401 a and 401 b over well 403,while traveling assemblies 419 a and 419 b are in their respectiveretracted positions (i.e., close to towers 401 a, 401 b, respectively)near the top of towers 401 a, 401 b, and top drive 408 b is coupled totubular 416 via, e.g., a hook, at make-up height for tubular 416 (i.e.,where tubular 416 can be connected to tubular 417); (2) unless otherwisereceived by traveling assembly 419 a, lowering traveling assembly 419 ato receive tubular 415 from a stored position (e.g., on or under rigfloor 410) and coupling tubular 415 to top drive 408 a while moving topdrive 408 b and tubular 416 away from tower 401 b via, e.g., retractionmechanism 409 b, and over the center of well 403; (3) coupling tubular416 to tubular 417 via, e.g., threading, and lowering tubular 416 (andtubular 417) into well 403 while hoisting tubular 415 to make-up heightfor tubular 415; (4) decoupling top drive 408 b from tubular 416 whentubular 416 is at make-up height for tubular 415 and moving top drive408 b toward tower 401 b via, e.g., retraction mechanism 409 b; (5)moving top drive 408 a and tubular 415 away from tower 401 a via, e.g.,retraction mechanism 409 a, and over well 403, and coupling tubular 415to tubular 416 via, e.g., threading; (6) unless otherwise received bytraveling assembly 419 b, receiving by traveling assembly 419 b tubular414 from a stored position (e.g., on or under rig floor 410) andcoupling tubular 414 to top drive 408 b via, e.g., a hook, and hoistingtubular 414 to make-up height for tubular 414 while lowering tubular 415(and tubular 416) into well 403; (7) decoupling top drive 408 a fromtubular 415 via, e.g., threading, when at make-up height for tubular414, and moving top drive 408 a toward tower 401 a via, e.g., retractionmechanism 409 a; and (8) unless otherwise received by traveling assembly419 a, receiving by traveling assembly 419 a tubular 407 from a storedposition (e.g., on or under rig floor 410) and coupling tubular 407 totop drive 408 a via, e.g., a hook, while moving top drive 408 b andtubular 414 away from tower 401 b via, e.g., retraction mechanism 409 b,and over the center of well 403. Steps 3-8 can be repeated forsubsequent tubulars until all tubulars desired to be tripped into well403 have been tripped into well 403.

More generally, a method for isochronously tripping tubulars into a wellis described with reference to FIG. 4j . Such a method may include:rotating first and second towers over the same well and receiving afirst tubular by the first tower while the second tower is positionedoff the center of the well; positioning the first tubular over thecenter of the well by operation of the first tower and lowering thefirst tubular into the well by operation of the first tower, whilereceiving a second tubular by the second tower; and receiving a thirdtubular by the first tower while positioning the second tubular over thewell center by operation of the second tower, coupling the secondtubular to the first tubular via, e.g., threading, and lowering thesecond tubular into the well by operation of the second tower. Thesecond and third steps can then be repeated with subsequent tubulars(modifying the second step to further couple any tubular received by thefirst tower to the previous tubular before lowering it into the well)until all tubulars desired to be run into the well are run into thewell.

The above specification and examples provide a complete description ofthe structure and use of illustrative embodiments. Although certainembodiments have been described above with a certain degree ofparticularity, or with reference to one or more individual embodiments,those skilled in the art could make numerous alterations to thedisclosed embodiments without departing from the scope of thisinvention. As such, the various illustrative embodiments of the methodsand systems are not intended to be limited to the particular formsdisclosed. Rather, they include all modifications and alternativesfalling within the scope of the claims, and embodiments other than theone shown may include some or all of the features of the depictedembodiment. For example, elements may be omitted or combined as aunitary structure, and/or connections may be substituted. Further, whereappropriate, aspects of any of the examples described above may becombined with aspects of any of the other examples described to formfurther examples having comparable or different properties and/orfunctions, and addressing the same or different problems. Similarly, itwill be understood that the benefits and advantages described above mayrelate to one embodiment or may relate to several embodiments.

The schematic flow chart diagrams presented herein are generally setforth as a logical flow chart diagram. The depicted order, labeledsteps, and described operations are indicative of aspects of methods ofthe invention. Other steps and methods may be conceived that areequivalent in function, logic, or effect to one or more steps, orportions thereof, of the illustrated method. Additionally, the formatand symbols employed are provided to explain the logical steps of themethod and are understood not to limit the scope of the method. Althoughvarious arrow types and line types may be employed in the flow chartdiagram, they are understood not to limit the scope of the correspondingmethod. Indeed, some arrows or other connectors may be used to indicateonly the logical flow of the method. For instance, an arrow may indicatea waiting or monitoring period of unspecified duration betweenenumerated steps of the depicted method. Additionally, the order inwhich a particular method occurs may or may not strictly adhere to theorder of the corresponding steps shown.

The claims are not intended to include, and should not be interpreted toinclude, means-plus- or step-plus-function limitations, unless such alimitation is explicitly recited in a given claim using the phrase(s)“means for” or “step for,” respectively.

What is claimed is:
 1. A drilling apparatus comprising: two or moredrilling towers configured to access a common well center, wherein atleast one of the two or more drilling towers is configured to rotatebetween the common well center and at least one other well center. 2.The apparatus of claim 1, wherein at least one of the two or moredrilling towers are configured to rotate between a plurality of wellcenters.
 3. The apparatus of claim 2, wherein the two or more drillingtowers are located on a rig, and wherein at least one of the pluralityof well centers is located transversely off the rig.
 4. The apparatus ofclaim 2, wherein the at least one of the plurality of well centers isnot located along the longitudinal axis of the rig and/or not locatedalong the circular path of at least one of the two or more towers. 5.The apparatus of claim 1, wherein at least one of the two or more towersincludes an adjustable crown sheave configured to reposition a loadpath.
 6. The apparatus of claim 1, wherein the two or more drillingtowers are configured to be simultaneously rotated over the common wellcenter.
 7. The apparatus of claim 6, further comprising a retractabletraveling assembly configured to move vertically along at least one ofthe two or more drilling towers.
 8. The apparatus of claim 7, whereinthe traveling assembly further comprises at least one of a top drive, aswivel, and a hook.
 9. The apparatus of claim 6, wherein the two or moretowers comprise drill lines configured as offset from one another toprevent interference between a drill line of a first tower and a drillline of a second tower when the first tower and the second tower arepositioned over the common well center.
 10. The apparatus of claim 6,wherein the two or more towers comprise drill lines configured toterminate at different vertical or horizontal locations to preventinterference between a drill line of a first tower and a drill line of asecond tower when the first tower and the second tower are positionedover the common well center.
 11. The apparatus of claim 1, furthercomprising a motion compensating device disposed on at least one of thetwo or more drilling towers and configured to compensate for relativemotion versus the seabed on the at least one of the two of more drillingtowers.
 12. The apparatus of claim 1, wherein the two or more towershave different fixed heights.
 13. The apparatus of claim 1, wherein atleast one of the two or more towers is configured with variable heights,wherein the at least one of the two or more towers comprises atelescoping device configured to provide a variable height.
 14. Theapparatus of claim 1, further comprising a brace between the two or moretowers, wherein the brace is configured to maintain clearance betweenthe two or more towers.
 15. The apparatus of claim 14, wherein the bracecomprises brace supports, and wherein the brace is configured to permitthe two or more towers to rotate through the brace supports.
 16. Theapparatus of claim 1, wherein the two or more towers are configured totrip tubulars into or out of a well.
 17. The apparatus of claim 16,wherein the two or more towers are configured to move tubulars alongdifferent spatial paths during tripping.
 18. The apparatus of claim 1,wherein the two or more towers are configured to lift together a singleload disposed over the common well center.
 19. The apparatus of claim 1,wherein each of the two or more towers is configured to simultaneouslyperform different functions.
 20. A method for performing an operation,the method comprising: rotating a first tower over a well; performing afirst operation over the well by the first tower; rotating a secondtower over the well; and performing a second operation over the well bythe second tower.
 21. The method of claim 20, wherein the first andsecond operation are performed at the same time.
 22. The method of claim21, wherein the first operation and the second operation are operationsfor tripping tubulars into a well.
 23. The method of claim 21, whereinthe first operation and the second operation are operations of anisochronous tripping operation.
 24. The method of claim 21, wherein thefirst operation and the second operation are operations in a heavy liftoperation to lift a load, wherein the load is larger than a capacity ofeither the first tower or the second tower alone.